Enhanced oil recovery process including the simultaneous injection of a miscible gas and water

ABSTRACT

An enhanced oil recovery process comprises of the at least periodic introduction of (i) a non-condensible gas preferably selected from among carbon dioxide, nitrogen, methane or mixtures thereof, and (ii) an aqueous drive solution, preferably brine, into a reservoir formation. In this process, the half cycle of non-condensible gas injection, prior to aqueous drive fluid injection, measured in hydrocarbon pore volume is less than 0.25%. In this preferred embodiment, the non-condensible gas, e.g., carbon dioxide, and water, are simultaneously injected into the formation.

This application is a divisional, of application Ser. No. 08/269,581,filed Jul. 1, 1994, now U.S. Pat. No. 5,515,919.

BACKGROUND OF THE INVENTION

This invention relates to an enhanced off recovery process and inparticular, a process for enhancing the recovery of oil through fiesimultaneous introduction of a non-condensible miscible gas, e.g.,carbon dioxide, and an aqueous drive fluid, e.g., brine.

Many petroleum producing formations require assistance to economicallyproduce hydrocarbons therefrom. In particular, the use of primaryproduction techniques, i.e., the use of only the initial formationenergy to recover the crude oil, typically recovers less that 50 % Ofthe original oil present in the formation. Even after the secondarytechnique of waterflooding, a significant portion of the oil remainsbehind.

To solve this problem, the art has looked to the use of certain enhancedoil recovery (EOR) techniques. These techniques can be generallyclassified as thermally based recovery methods, i.e., utilizing steam,or gas-drive based methods that can be operated under either miscible orimmiscible conditions. That is, in the gas-drive based methods, forcertain crude oils and formation temperatures, the gases, which aretypically non-condensible, become miscible with the oil above a pressureknown as the minimum miscibility pressure. Above this pressure, thesenon-condensible gases attain a supercritical state havingcharacteristics of both gases and liquids.

However, because the viscosity of these non-condensible fluids, such ascarbon dioxide, is significantly less than that of the crude oil presentwithin the reservoir (carbon dioxide has only 5 to 10% of the viscosityof, e.g., light oil), significant channelling of the gas typicallyoccurs and as a result much, if not most, of the oil in the reservoir isnonetheless bypassed by the gas. In particular, because of thedifferences in viscosity, "breakthrough" of the carbon dioxide occursand the subsequently injected gas preferentially follow the path of thebreakthrough, thereby resulting in poor sweep efficiencies in thereservoir.

One technique for decreasing this mobility of miscible CO₂ in thereservoir involves the use of a drive fluid, i.e., a higher viscosityfluid used to "push" the slug of carbon dioxide. One example of such aprocess is the Water Alternating-Gas (WAG) process. Such a processcomprises the alternating introduction of a non-condensible, misciblegas such as carbon dioxide, nitrogen, methane, mixtures of methane withethane, propane, butane and higher homologues, with an aqueous drivefluid, e.g., brine. In this process, the water serves to prevent themobile non-condensible gas from channelling directly from an injectionwell to a producing well. This ability to slow down gas movement throughthe reservoir is capable of providing improved contact between the gasand the oil remaining in the reservoir.

However, this process is not without its own set of problems. Forexample, the gas and the aqueous drive fluid may not be distributeduniformly within the reservoir. In particular, due to differences inviscosity between the water and the carbon dioxide, "gravity override",i.e., gravity segregation of the components, can occur, therebydecreasing the effectiveness of the recovery process. In addition, theWAG process faces certain economic limitations, both with respect to thecost of the non-condensible gas and the labor intensive nature ofcertain aspects of the process, e.g., alternating between the twocomponents.

Thus, the need still exists for an improved process for the enhancedrecovery of petroleum employing a non-condensible, miscible gas.

SUMMARY OF THE INVENTION

Among other aspects, of the present invention is based on the surprisingdiscovery that improvements in both recovery and economics can beprovided when the half cycle of non-condensible gas injection to aqueousdrive fluid, as measured in hydrocarbon pore volume, in a WAG is reducedto a value less than 0.25% In fact, a still more preferred embodiment ofthe invention involves the simultaneous injection of the two components.

In one aspect, the process of the present invention comprises at leastperiodically injecting each of (i) a non-condensible gas and (ii) anaqueous drive fluid, either simultaneously or sequentially, into anoil-bearing formation with the proviso that, if injected sequentially, ahalf cycle of non-condensible gas injection, measured in hydrocarbonpore volume, is less than 0.25%.

In one particularly preferred embodiment of this process, carbon dioxideis employed as the non-condensible gas, the drive fluid is a brine, andthe miscible gas and water are simultaneously injected into theformation.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic flow diagram of a simultaneous injection systemfor introduction of both a non-condensible gas and water and which canbe employed in one preferred embodiment of the process of the presentinvention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS OF THE INVENTION

As discussed above, the process of the present invention involves theuse of a "non-condensible" gases such as carbon dioxide, nitrogen,methane, and the like. In general, such gases have a relatively lowcritical point, that the temperature above which the gas cannot becompressed into liquid. Moreover, such gases are at least partiallysoluble in the oil. Thus, because these gases, although not condensible,are in fact miscible in the oil, they are absorbed by the petroleum, soas to reduce the viscosity of the oil and/or to increase its mobilitythrough the formation. At the same time the increased pressure of thegas facilitates movement of residual petroleum in the formation to thereservoir well or wells. Thus, in the context of the present inventionthey are termed "non-condensible, miscible" gases.

Although the following discussion will focus on one embodiment of theinvention relating to the use of miscible carbon dioxide, the process ofthe present invention is equally applicable to other non-condensible,miscible gases.

The other main component of the process of the present invention iswater, i.e., an aqueous drive fluid. This water can be in any form orrecognized in the art, e.g., reservoir brines, and as such is notdiscussed in detail here.

Moreover, the Water Alternating-Gas (WAG) process is itself recognizedand in general involves an alternating sequence of water and gasinjection until a desired gas slug size is obtained. When the desiredsize slug is obtained, a chase water flood injection is typicallyperformed. See, for example, U.S. Pat. No. 3,529,668. These gas slugsare measured in terms of hydrocarbon pore volume (HCPV), e.g., a typicalslug is from about 10 to as high as 30 or 40% HCPV. The gas slug size isnot considered critical to the present invention and will depend, e.g.,on reservoir conditions.

Another recognized parameter of the WAG process is the WAG ratio, i.e.,the ratio of a water to gas in the process. In this regard, the relativeamounts selected are effective to provide for both miscible conditionsfor the gas in the oil while also minimizing (and optimally preventing)"channeling" or "breakthrough" of the gas. Once again, in the process ofthe present invention, the WAG ratio is not critical, however, a WAGratio can typically range from 1:4 to 5:1, with a preferred ratio incertain environments being from 1:1 to 4:1.

Moreover, it is within the context of the present invention to employ"tapering" of this ratio, which involves increasing the WAG ratio, e.g.,from 1:1 to 2:1 to 3:1, at decreased gas slug size in order to decreasethe required gas production and therefore improve the overall economicsof the process.

Yet another parameter of the WAG process is the half cycle, i.e., theamount, measured in hydrocarbon pore volume, of non-condensible gasinjected prior to switching to water. Previous WAG processes havetypically employed half cycles on the order of 1.5 to 3.0% HCPV.Recently, half cycles as low as 0.25 have been utilized. In the processof the present invention, the inventors have discovered that the use ofhalf cycle less than 0.25%, provides some distinct and unexpectedadvantages in terms of mixing and retention of the two components in theformation, and therefore lead to an improved recovery.

One particularly preferred embodiment of the present invention involvesthe simultaneous injection of the non-condensible gas and water into thereservoir.

Any method which can effectively provide for the simultaneous injectionof the gas and the drive fluid can be employed in this embodiment of theinvention. For example, one possible technique includes the use of checkvalves, which can be either manually or automatically controlled by,e.g., a control loop.

As a specific example of one arrangement for use in the process of thepresent invention, attention is directed to the drawing figure. Asillustrated therein, a source of non-condensible gas, e.g., CO₂, 1 , anda source of water, 2, are both connected to an injection means, 3, viacontrol valves 4. These control valves can be operated for an example,by a computer, 5, (which, as illustrated in the drawing, can even besolar powered) and flow meters, 6. Such an arrangement allows for therates of the two components to be set based upon, for example, the totaldesired injection rate and the WAG ratio.

Moreover, the simultaneous injection process is preferred because itprovides for a unique combination of improved efficiency, i.e.,particularly in the areas of mixing and retention of the non-condensiblegas and water, as well as economics, e.g., the ability to reduce or eveneliminate certain labor intensive procedures associated with the WAGprocess. In particular, this process can provide increased yields of offfrom the formation while significantly decreasing CO₂ requirements, e.g,on the order of 10% or more.

While the present invention has been discussed in terms of variouspreferred embodiments, various modifications, substitutions, and changesmay be made by those skilled in the art without departing from thespirit thereof. Accordingly, it is believed that scope of the presentinvention should be determined only in terms of the appended claims andequivalents thereof.

What is claimed is:
 1. A process for the enhanced recovery of oil froman oil-bearing reservoir formation comprising injecting effective oilproducing amounts of (i) a non-condensible gas and (ii) an aqueous drivefluid simultaneously into the formation characterized in that the gasand aqueous drive fluid begins from an initial preselected water to gasratio and increases to a ratio of 2:1 to 3:1 and wherein the amount ofsaid gas injected is effective to reduce the viscosity of the oil or toincrease its mobility through the reservoir formation.
 2. The processaccording to claim 1 wherein the non-condensible gas is selected fromamong carbon dioxide, nitrogen, and methane.
 3. The process according toclaim 1 wherein the non-condensible gas is carbon dioxide.
 4. Theprocess according to claim 1 wherein the aqueous drive solution isbrine.
 5. The process according to claim 1 wherein the non-condensiblegas is carbon dioxide, and the drive fluid is brine.
 6. The processaccording to claim 1, wherein the preselected water to gas ratio isabout 1:1.
 7. In an enhanced oil recovery process including at leastperiodic injection of (i) a non-condensible gas and (ii) an aqueousdrive fluid into a reservoir formation, wherein the improvementcomprises injecting (i) and (ii) simultaneously into the reservoirformation from an initial water to gas ratio and increases to a higherratio of between 2:1 and 3:1 wherein the amount of non-condensible gasinjected as measured in hydrocarbon pore volume, is less than 0.25% andwherein the amount of said non-condensible gas injected is effective toreduce the viscosity of the oil or to increase its mobility through thereservoir formation.
 8. The process according to claim 7, wherein thenon-condensible gas comprises carbon dioxide, nitrogen, methane ormixtures thereof.
 9. The process according to claim 7, wherein thenon-condensible gas is carbon dioxide.
 10. The process according toclaim 7, wherein the aqueous drive fluid is brine.
 11. The processaccording to claim 7, having an initial water to gas ratio of about 1:1.